Exploration wells are often drilled for the purpose of discovering petroleum reserves. Determining such reserves may include, among other things, determining oil bearing zones, petroleum in place, recoverable petroleum, and value of petroleum. Determining recoverable petroleum and the value of petroleum often involves collecting a sample of fluid at reservoir conditions. For the purpose of this application, this sample is called a “live fluid” or “live oil.”
A composition (or assay) of the fluid may be used to determine the value of the fluid, but also physical properties of the fluid such as Gas to Oil Ratio (“GOR”), bubble point, viscosity, wax precipitation point, asphaltene precipitation point, and purely chemical properties such as compatibility with other fluid, scaling issues, hydrate formation properties, etc. The ability of analysis to determine the properties listed above and others may hinge on the drilling fluid filtrate contamination level of the fluids especially when the drilling contaminate is organic based mud (drilling fluid) filtrate (“OBM” filtrate).
In practice many properties of a contaminated sample may be backed out if the contamination level is known. In some circumstances, other properties of the drilling fluid may not be backed out and may be determined only with sufficiently pristine samples. Some properties of the fluid are well defined by equation-of-state models that often are functions solely of live fluid composition. Therefore, it is useful to determine live fluid composition from a live fluid sample. Determining live fluid composition can be challenging, especially in a down hole environment.